Method for determining parameters of a bottomhole and a near-bottomhole zone of a wellbore

ABSTRACT

Whiles moving a pipe string in a wellbore during tripping operations, pressure and temperature are measured. Based on the measured pressure and temperature, such parameters of a bottomhole and a near-bottomhole zone of the wellbore are calculated as skin factor, permeability, reservoir thickness, bottomhole pressure, and outflow or inflow from/to the zone under consideration.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to Russian Application No. RU2012155806filed Dec. 24, 2012, which is incorporated herein by reference in itsentirety.

FIELD OF THE INVENTION

The invention relates to the field of completion and testing of wells inthe oil and gas industry and is intended for estimation of parameters ofa bottomhole and a near-bottomhole zone of a wellbore such as, forexample, skin factor, permeability, reservoir thickness, bottomholepressure, and outflow out of and/or inflow into the zone underconsideration.

BACKGROUND OF THE INVENTION

In the prior art, various methods for determining parameters of abottomhole and a near-bottomhole zone are known. In particular, the U.S.Pat. No. 4,799,157 describes a method for determining permeability andskin factor of two layers of a single reservoir. The method consists inperforming two consecutive drill-hole hydrodynamic tests by means ofcreating a drawdown at the bottomhole with swapping of the productionlogging tool and subsequent interpretation of production rate andpressure data.

U.S. Pat. No. 5,337,821 shows a method for calculating formation fluidtransmissibility as well as a method and metering apparatus formeasuring production rates, open flow potential of the well, and fordetermining the dependency of near-bottomhole formation damage versusproduction rate. Measurements are conducted after deployment of the toolto a preset depth and isolation of intervals with the use of inflatableelastomer packers.

U.S. Pat. No. 7,675,287 describes a method for estimation of skin factorof a subsurface reservoir inside a wellbore by means of deployment of ameasuring apparatus to a preset depth and measuring nuclear magneticresonance of the formation at multiple depths.

US Patent Application No. 2011/0087471 proposes to establish afunctional relationship between properties of the reservoir,characteristics of the near-bottomhole zone/completion of the well, andthe measurable characteristics of the well. Confirmed values ofreservoir properties, for example, permeability; characteristics of thenear-wellbore zone/completion, for example, skin factor, are determinedprovided that the functional relationship is established.

The common drawback of the patents and patent applications is that allof them require special equipment or special downhole operations fordetermining properties of the bottomhole and the near-bottomhole zone.The distinction of the present invention is that information usuallyavailable in the course of well tests or well operation is used fordetermining properties of the bottomhole and the near-bottomhole zone.In other words, no non-standard equipment or additional operations arerequired for determining the parameters.

SUMMARY OF THE INVENTION

The invention provides a possibility of determining parameters of abottomhole and a near-bottomhole zone such as bottomhole pressure,during tripping operations with subsequent calculation of fluidinflow/outflow at the bottomhole, and calculation of skin factor,permeability or reservoir thickness. Realization of the proposed methodcan be achieved with the use of conventional pressure gauges that arewidely used in the petroleum industry, without deployment of specialtools into a well.

In accordance with the proposed method, pressure and temperature aremeasured in the process of moving a pipe string within a wellbore.Parameters of a bottomhole and a near-bottomhole zone are estimatedbased on results of the measurements.

The parameters of the bottomhole and the near-bottomhole zone mayinclude a flowing bottomhole pressure, dynamics of fluid loss into areservoir, dynamics of fluid inflow from a reservoir, total fluid lossor fluid inflow volume, skin factor, reservoir permeability orthickness.

According to one of embodiments of the disclosure pressure andtemperature are measured by at least one pressure and temperature gaugeinstalled at any place of the pipe string.

According to another embodiment of the disclosure pressure andtemperature are measured by two pressure and temperature gauges, onegauge is installed above a packer and the other—below a packer.

According to one more embodiment of the disclosure pressure andtemperature are measured by pressure and temperature gauge installed inthe pipe string in such a way that it is disposed as close as possibleto the reservoir upon the end or running the pipe string into thewellbore to the required depth.

In accordance with another embodiments of the disclosure pressure andtemperature are measured by at least one pressure gauge and onetemperature gauge installed at any place of the pipe string.

According to one more embodiment of the disclosure pressure andtemperature are measured by at least one pressure gauge and onetemperature gauge installed in the pipe string in such a way that theyare disposed as close as possible to the reservoir upon the end ofrunning the pipe string into the wellbore to the required depth.

The pipe string may be equipped with any additional tools, for example,samplers.

In accordance with another embodiment of the disclosure, pressure andtemperature are measured in the process of running the pipe string intothe wellbore. Pressure and temperature measurements can be measuredprior to perforating the interval.

In accordance with another embodiment of the disclosure, pressure andtemperature are measured in the process of pulling the pipe string outof the wellbore. Pressure and temperature can be measured afterperforating the interval.

In accordance with one more embodiment of the disclosure, pressure andtemperature are measured both in the process of running the pipe stringinto the wellbore and in the process of pulling the pipe string out ofthe wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention is explained by drawings where FIG. 1 shows a system forcarrying out tripping operations and measurements;

FIG. 2 shows a displacement process in a simplified geometrical form;

FIG. 3 shows the geometry used in the calculation example;

FIG. 4 shows a position of a liquid level in an annular space outside apipe string and a position of drill pipes with a formation (reservoir)testing arrangement along the wellbore as of the time of action;

FIG. 5 shows the determined flowing bottomhole pressure and the totalfluid loss volume.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

As is shown in FIG. 1, a pipe string 1 or pipe string 1 with additionaltools is run into a wellbore 2 from a surface 3 location for performanceof certain operations. A gauge 4 for measuring pressure and temperatureis installed in the pipe string 1. An additional gauge 5 or severaladditional gauges for measuring pressure and temperature may beinstalled in the system. The pipe string 1 is run into the wellbore 2until it reaches a position 6 at a certain point in front of asubsurface reservoir 7 or close to it. Pressure and temperature arerecorded during the entire period the pipe string 1 is being run intothe wellbore from the surface 3 to the position 6. After performing therunning-in-hole operation, all planned downhole operations, and pullingthe pipe string to the surface, the pressure and temperature gauges areretrieved to the surface with the measurements that were recorded duringthe tripping operations and the measurements recorded in the process ofperformance of the planned downhole operations.

In case of using two pressure and temperature gauges, one of the gaugesmay be installed above a packer and the other below the packer. Thearrangement with the two gauges makes it possible to determine density pproceeding from the pressure difference by readings of the two pressuregauges. Using the formula of hydrostatic pressure, we obtain:

${\rho (t)} = \frac{\Delta \; {p_{g}(t)}}{{gl}_{g}\cos \; \theta_{g}}$

where g is gravity constant, l_(g) is distance between the two pressuregauges, and θ_(g) is a mean inclination angle of this part of thewellbore. Note that this formula is valid for slow processes in whichfrictional pressure losses play a less significant role than thehydrostatic pressure difference. Temperature measurements may be usedfor determining the relationship between properties of the fluid at thesurface and at the point of measurement downhole.

Let us consider volume balance during running the pipe string in hole.For the sake of simplicity, we will neglect compressibility of fluidsand assume that the level of liquid in the annulus rises strictlyvertically while movement of the drill string or tubing string with thebottomhole arrangement for performance of formation (reservoir) testingtakes place along a slant line (see FIG. 2).

The moving drill pipe string with the bottomhole arrangement forperformance of formation (reservoir) testing displaces a certain volumeof fluid ΔV_(DST) during a period of time Δt. At the same time, thefluid volume in an annulus increases by ΔV_(an) and volume ΔV_(r) istaken up by the reservoir. Hence, in this case we have

ΔV _(DST) =ΔV _(an) +ΔV _(r)  (1)

These volumes can be expressed simpler in the following form

ΔV_(DST)=A_(DST)Δz_(DST)

ΔV_(an)=A_(an)Δz_(an)

ΔV_(r)=2πr_(w)hΔr=Q_(loss)Δt

where Δz_(DST) is a measured depth of drill pipe string advance duringtime Δt (8 in FIG. 2), Δz_(an) is a height of rise of a fluid column inthe annulus during time Δt (9 in FIG. 2), A_(an) is a cross sectionalarea available for flow in the annulus, A_(DST) is a cross sectionalarea of the drill pipe string calculated at its outside diameter, h is adifference between the measured depths of reservoir top and bottom(reservoir thickness, 10 in FIG. 2) or length of a perforated interval,Δr is a depth of wellbore fluid invasion into the reservoir (11 in FIG.2), r_(w) is a radius of the wellbore (12 in FIG. 2), Q_(loss) is avolume rate of outflow from the wellbore to the reservoir.

Having substituted the last expression into Equation (1) and havingdivided by Δt, we obtain

$\begin{matrix}{{A_{DST}\frac{\Delta \; z_{DST}}{\Delta \; t}} = {{A_{an}\frac{\Delta \; z_{an}}{\Delta \; t}} + Q_{loss}}} & (2)\end{matrix}$

The term in the left-hand part of Equation (2) expresses the velocity ofrunning the drill string with the bottomhole arrangement for performanceof formation (reservoir) testing in the wellbore

${v_{DST}(t)} = \frac{\Delta \; z_{DST}}{\Delta \; t}$

The value of this velocity v_(DST) is assumed as a set value. Usuallythis velocity is of the order of several centimeters per second. Let usconsider now the first term in the right-hand part of Equation (2). Theincrement of fluid level in the annulus is proportional to theincreasing hydrostatic bottomhole pressure which, for slow processes ina near-vertical wellbore equals chiefly the hydrostatic component

$\frac{\Delta \; z_{an}}{\Delta \; t} = {\frac{1}{\rho \; g}\frac{\Delta \; p_{wf}}{\Delta \; t}}$

where Δp_(wf) denotes the change in bottomhole pressure during time Δt.

Note that more complex geometrical characteristics and velocityintervals can be taken into consideration in the last expression. Thesecond term in the right-hand part of the equation can be expressed, forexample, from the steady-state relationship of fluid inflow in adevelopment well (the relationship of flowing bottomhole pressure versusflow rate)

$Q_{loss} = {\frac{2\; \pi \; {kh}}{\mu \left( {{\ln \left( {r_{e}/r_{w}} \right)} + s} \right)}\left( {p_{wf} - p_{e}} \right)}$

Here k is permeability, μ is viscosity, r_(e) is equivalent radius ofpressure, s is skin factor, p_(e) is formation pressure determined atthe equivalent radius of pressure.

Substituting the last tree equalities for Equation (2) with Δt→0, weobtain a simple ordinary differential equation of first order

$\begin{matrix}{\frac{p_{wf}}{t} = {\frac{\rho \; g}{A_{an}}\left( {{A_{DST}{v_{DST}(t)}} - {{PI}\left( {p_{wf} - p_{e}} \right)}} \right)}} & (3)\end{matrix}$

where PI is productivity index of the well.

${PI} = \frac{2\; \pi \; {kh}}{\mu \left( {{\ln \left( {r_{e}/r_{w}} \right)} + s} \right)}$

Equation (3) can be written in explicit discretized form.

$\begin{matrix}{p_{wf}^{n + 1} = {p_{wf}^{n} + {\Delta \; t\frac{\rho \; g}{A_{an}}\left( {{A_{DST}v_{DST}^{n}} - {{PI}\left( {p_{wf}^{n} - p_{e}} \right)}} \right)}}} & (4)\end{matrix}$

Equation (4) is easily solved numerically for calculating a hydrodynamicbottomhole pressure p_(wf), which in turn makes it possible to calculatea volume flow rate of fluid uptake by the reservoir Q_(loss)(t). Skinfactor s is determined by matching the value satisfying the presetparameters, problem specifications, and satisfying requirements for thecheck-out parameters (see below). It is necessary to note that in thisproblem value of permeability k might become an unknown value (value tobe determined). In this case it could be found with a preset skin factors and reservoir thickness h. On the other hand, reservoir thickness alsomight be unknown (value to be determined). In such case, it could befound with a preset skin factor s and permeability k.

Reliability of results predicted by the model can be checked throughcalculation of the following check-up parameters: location of the drillstring with the bottomhole arrangement for performance of formation(reservoir) testing)

z _(DST)(t)=z _(DST)(0)−∫₀ ^(t) v _(DST)(t)dt  (5)

Height of fluid level in the annulus

$\begin{matrix}{{z_{an}(t)} = {{z_{an}(0)} + \frac{{p_{wf}(t)} - p_{e}}{\rho \; g}}} & (6)\end{matrix}$

and pressure of the lower pressure gauge

p _(gc)(t)=p _(e) −ρgz _(DST)(t) cos θ  (7)

It is necessary to pay attention to the fact that, for the sake ofsimplicity, values of both z_(DST)(t) and z_(an)(t) are measured alongthe wellbore, starting from the bottomhole.

As a particular example, let us consider a wellbore configuration shownin FIG. 3, which is characterized by the following parameters: length ofan inclined section l₁=2127.04 m (13 in FIG. 3), length of a verticalsection l₂=500 m (14 in FIG. 3), and an angle of inclination θ=20° (15in FIG. 3). Length of a perforated interval h=10 m, formation pressurep_(e)=200 bar (the reduced radius of pressure r_(e)=500 m), andformation permeability k=50 mD. In this example, value of skin factor isan an unknown value. Fluid density in the flow ρ=1000 kg/m³, andviscosity μ=1. Assume that during running into the wellbore a stringtouches a liquid for the first time at an inflection point at whichbottomhole pressure equals the value of hydrostatic pressure,ρgh₁=p_(e). Proceeding from this equation, we see that the height offluid column in the wellbore at start of the operation was h₁=2000 m (16in FIG. 3).

The tripping operation in this case consists of two periods of runningthe drill string into the wellbore and a short period of pulling thestring out of the wellbore between the above-said running periods, tillthe end of moving the string. Average velocity was adjusted in order thevalue of z_(DST) calculated with the use of Equation (5) to equal zerowhen the string stops its movement (the lower tool achieves the terminalmeasured depth along the wellbore, curve 17 in FIG. 4). As a result ofsuch adjustment, we obtain the absolute value of v_(DST)=0.03735 msec(see FIG. 4).

After the value of v_(DST) has been selected for the preset parameters,it is necessary to make sure that the value of max(z_(an))=l₁+l₂, as ofthe moment of end of tripping operations (curve 18 in FIG. 4) indicatesthat the fluid level in the annulus have risen to the heightcorresponding to the reading of correct hydrostatic pressure on thepressure gauge. This automatically equates the calculated value ofhydrostatic pressure with the estimated value on the pressure gauge thatis calculated with the use of Equation (7). A good match is obtained forthe skin factor value s=60 (see FIG. 5 where curve 19 denotes flowingbottomhole pressure, curve 20 denotes pressure on the gauge obtainedwith the use of Equation (7) and curve 21 denotes the total outflow intothe reservoir). This figure also shows total losses ∫Q_(loss)dt.

The present method can be applied for cases with more complexgeometrical characteristics as well.

1. A method for determining parameters of a bottomhole and anear-bottomhole zone in a wellbore drilled in a reservoir, the methodcomprising: measuring pressure and temperature while moving a pipestring in the wellbore; and calculating parameters of the bottomhole andthe near-bottomhole zone based on the measured pressure and temperature.2. The method of claim 1, wherein the parameters of the bottomhole andthe near-bottomhole zone are a flowing bottomhole pressure, dynamics offluid uptake by the reservoir, dynamics of fluid inflow from thereservoir, total volume of fluid loss or inflow, skin factor,permeability, and reservoir thickness.
 3. The method of claim 1, whereinpressure and temperature are measured by at least one pressure andtemperature gauge installed along the pipe string.
 4. The method ofclaim 3, wherein pressure and temperature are measured by two pressureand temperature gauges, one of which is installed above a packer and theother below a packer.
 5. The method of claim 3, wherein pressure andtemperature are measured by a pressure and temperature gauge installedin the pipe string in such a way that it is disposed as close aspossible to the reservoir upon the end of running the pipe string to therequired depth in the wellbore.
 6. The method of claim 1, whereinpressure and temperature are measured by at least one pressure gauge andone temperature gauge installed at any place of the pipe string.
 7. Themethod of claim 6, wherein pressure and temperature measurements aremeasured by at least one pressure gauge and one temperature gaugeinstalled in the pipe string in such a way that they are disposed asclose as possible to the reservoir upon the end or running the pipestring to the required depth in the wellbore.
 8. The method of claim 1,wherein the pipe string is equipped with additional tools.
 9. The methodof claim 1, wherein pressure and temperature are measured in the processof running the pipe string into the wellbore.
 10. The method of claim 9,wherein pressure and temperature are measured prior to perforating theinterval.
 11. The method of claim 1, wherein pressure and temperatureare measured in the process of pulling the pipe string out of thewellbore.
 12. The method of claim 11, wherein pressure and temperatureare measured after perforating the interval.
 13. The method of claim 1,wherein pressure and temperature are measured both in the process ofrunning the pipe string in the wellbore and in the process of pullingthe pipe string out of the wellbore.